Much of the world's oil is found in the form of oil sands, large deposits of which are found in Alberta, Canada. The bitumen in oil sands cannot typically be pumped from the ground in its natural form because of its high viscosity. Oil sand deposits near the surface may be recovered by open-pit mining techniques, using powered shovels to remove the oil sand and load the trucks for transport to an extraction plant. Because the bitumen itself is a highly viscous material, separating it from the sands poses certain practical difficulties. The extraction of bitumen from oil sands mined in such a manner involves the liberation and separation of bitumen from the associated sands in a form that is suitable for further processing to produce a marketable product. Among several processes for bitumen extraction, the Clark Hot Water Extraction (CHWE) process represents a well-developed commercial recovery technique. In the CHWE process, mined oil sands are mixed with hot water to create a slurry suitable for extraction. Caustic is added to adjust the slurry pH to a desired level and thereby enhance the efficiency of the separation of bitumen. Recent industry developments have shown the feasibility of operating at lower temperatures and without caustic addition in the slurrying process.
The result of most of the CHWE processes is an extract that typically comprises two parts: a hydrocarbon predominant phase (known as a bitumen froth stream), and a tailings stream made up of coarse solids, some fine solids, and water. The specific properties of the tailings will vary depending on the extraction method used, but the tailings essentially comprise spent water, reagents (e.g. surfactants), and waste ore once the recovered bitumen has been removed. A typical composition of the bitumen froth stream is about 60 wt % bitumen, 30 wt % water and 10 wt % mineral matter (solids), with some variations to account for the extraction and processing conditions. The water and mineral matter in the froth are considered as contaminants and must be either essentially eliminated or reduced to a level suitable for pipeline transportation, feed to an oil refinery or an upgrading facility.
The processes to reject the water and mineral matter contaminants are known as froth treatment processes. Due to the high viscosity of bitumen, the first step in such processes is usually the introduction of a solvent. There are two major commercial approaches to reject the froth contaminants, namely naphtha solvent-based froth treatment and paraffinic solvent-based froth treatment. Solvent addition (dilution) increases the density differential between bitumen and water and mineral matter and enables contaminants rejection, which can be carried out by any number of methods, such as centrifugation or gravity separation using multi-stage gravity settling units. The separation schemes generally result in a product effluent stream of diluted bitumen (“dilbit”) and a reject or tailings stream, commonly referred to as the froth treatment tailings, comprising mineral matter, water, residual solvent, and some residual bitumen. More specifically, in a paraffinic froth treatment process the solvent dilution induces the precipitation of asphaltenes from the bitumen as an additional contaminant that results in an improvement in the efficiency of the contaminant rejection process.
An example of naphtha froth treatment (NFT) is disclosed in U.S. Pat. No. 5,236,577. Addition of naphtha and separation may yield a bitumen product containing 1 to 3 wt % water and <1.0 wt % solids. Such product composition does not meet pipeline specifications and renders the NFT product stream unsuitable for transportation through a common pipeline carrier.
Examples of paraffinic froth treatment (PFT) are described in Canadian Patents Nos. 2,149,737 and 2,217,300. The addition of sufficient amounts of paraffinic solvent results in asphaltene precipitation, formation of aggregates with the contaminants (entrained water and carryover solids in the froth), and settling. Conventional treaters which separate water and mineral matter will not remove very fine particulate (“fines”) from the froth. Therefore, PFT settling vessels are sized to allow gravity settling of fines and other contaminants to provide a solids-free dry bitumen product (<300 wppm solids, <0.5% BS&W) suitable for transportation in a common carrier to refineries. Bitumen of such quality is termed “fungible” because it can be processed in conventional refinery processes, such as hydroprocessing, without dramatically fouling the refinery equipment. However, PFT is energy-intensive and expensive and results in a waste stream of asphaltenes—a potentially valuable commodity.
The CHWE process, described above, is the most commonly employed water-based extraction process. In the case of water-based extraction, water is the dominant liquid in the process and the extraction occurs by having water displace the bitumen on the surface of the solids.
Solvent-based extraction processes for the recovery of the hydrocarbons have been proposed as an alternative to water-based extraction of mined oil sands. In the case of solvent-based extraction, the solvent is the dominant liquid and the extraction of the bitumen occurs by dissolving bitumen into the solvent. However, the commercial application of a solvent-based extraction process has, for various reasons, eluded the oil sands industry. A major challenge to the application of solvent-based extraction to oil sands is the tendency of fine particles within the oil sands to hamper the separation of solids from the hydrocarbon extract. Solvent extraction with solids agglomeration is a technique that has been proposed to deal with this challenge. The original application of this technology was coined Solvent Extraction Spherical Agglomeration (SESA). A more recent description of the SESA process can be found in Sparks et al., Fuel 1992(71); pp 1349-1353.
Previously described methodologies for SESA have not been commercially adopted. In general, the SESA process involves mixing oil sands with a hydrocarbon solvent, adding a bridging liquid to the oil sands slurry, agitating the mixture in a slow and controlled manner to nucleate particles, and continuing such agitation to permit these nucleated particles to form larger multi-particle spherical agglomerates for removal. The bridging liquid is preferably water or an aqueous solution since the solids of oil sands are mostly hydrophilic and water is immiscible with hydrocarbon solvents.
The SESA process described by Meadus et al. in U.S. Pat. No. 4,057,486, involves combining solvent extraction with solids agglomeration to achieve dry tailings suitable for direct mine refill. In the process, organic material is separated from oil sands by mixing the oil sands material with an organic solvent to form a slurry, after which an aqueous bridging liquid is added in the amount of 8 to 50 wt % of the feed mixture. By using controlled agitation, solid particles from oil sands come into contact with the aqueous bridging liquid and adhere to each other to form macro-agglomerates of a mean diameter of 2 mm or greater. The formed agglomerates are more easily separated from the organic extract compared to un-agglomerated solids. This process permitted a significant decrease in water use, as compared with conventional water-based extraction processes. Furthermore, the organic extract produced has significantly lower amounts of solids entrained within compared to previously described solvent-based extraction methods.
Solvent extracted bitumen has a much lower solids and water content than that of bitumen froth produced in the water-based extraction process. However, the residual amounts of water and solids contained in solvent extracted bitumen may nevertheless render the bitumen unsuitable for marketing. Removing contaminants from solvent extracted bitumen is difficult using conventional separation methods such as gravity settling, centrifugation or filtering.
Another example of a solvent-based extraction process is described in Canadian Patent Application Serial No. 2,724,806 (“Adeyinka et al.”), filed Dec. 10, 2010 and entitled “Processes and Systems for Solvent Extraction of Bitumen from Oil Sands”.
Solvent deasphalting has previously been proposed for product cleaning of solvent extracted bitumen. Deasphalting technologies are described in U.S. Pat. No. 4,572,777 (Peck), issued Feb. 25, 1986 entitled: Recovery of a carbonaceous liquid with a low fines content; and U.S. Pat. No. 4,888,108 (Farnand), issued Dec. 19, 1989 entitled: Separation of Fines Solids from Petroleum Oils and the Like. The solvent deasphalting processes described in these patents do not indicate the formation of a fungible product in a deasphalting step. The processes described in these patents are limited by the type of deasphalting solvent used and the proper deasphalting solvent to bitumen ratio required for optimal solids removal. The deasphalting process described were not specific and relied more on conventional deasphalting technologies, such as those commonly used in refineries to produce heavy crude, oils to upgrade heavy bottoms streams, and/or to deasphalt oil. However, these conventional deasphalting technologies operate at high temperatures and pressures, and at a low feed rate, compared to what would be required for a large scale production facility. These deasphalting technologies are expected to be even more energy-intensive and expensive than the PFT process. Furthermore, like PFT, a portion of the potentially valuable asphaltenes are removed from the bitumen product.
Where deposits lie well below the surface, bitumen may be extracted using in situ (“in place”) techniques. One example of an in situ technique is the steam-assisted gravity drainage method (SAGD). In SAGD, directional drilling is employed to place two horizontal wells in the oil sands—a lower well and an upper well positioned above it. Steam is injected into the upper well to heat the bitumen and lower its viscosity. The bitumen and condensed steam will then drain downward through the reservoir under the action of gravity and flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and bitumen are separated, and the bitumen is diluted with appropriate light hydrocarbons for transport to a refinery or an upgrader. An example of SAGD is described in U.S. Pat. No. 4,344,485 (Butler).
In other processes, such as in Cyclic Steam Stimulation (CSS), the same well is used both for injecting a fluid and for producing oil. In CSS, cycles of steam injection, soak, and oil production are employed. Once the production rate falls to a given level, the well is put through another cycle of injection, soak, and production. An example of CSS is described in U.S. Pat. No. 4,280,559 (Best).
Steam Flood (SF) involves injecting steam into the formation through an injection well. Steam moves through the formation, mobilizing oil as it flows toward the production well. Mobilized oil is swept to the production well by the steam drive. An example of steam flooding is described in U.S. Pat. No. 3,705,625 (Whitten).
Other thermal processes include Solvent-Assisted Steam Assisted Gravity Drainage (SA-SAGD), an example of which described in Canadian Patent No. 1,246,993 (Vogel); Vapour Extraction (VAPEX), an example of which is described in U.S. Pat. No. 5,899,274 (Frauenfeld); Liquid Addition to Steam for Enhanced Recovery (LASER), an example of which is described in U.S. Pat. No. 6,708,759 (Leaute et al.); and Combined Steam and Vapour Extraction Process (SAVEX), an example of which is described in U.S. Pat. No. 6,662,872 (Gutek), and derivatives thereof.
Presently, heavy oil and bitumen are upgraded by either thermal conversion processes which reject carbon typically as coke (delayed coking or fluid coking) or by hydroconversion/hydrocracking processes in which hydrogen is added to the heavy oil to improve properties and reject contaminants such as metals and sulfur. Although thermal conversion processes such as coking are widely practiced throughout the world and in the Athabasca region of Alberta, Canada, these processes are typically capital and operating cost intensive. Moreover, they require secondary hydrotreating to improve the quality of the coker liquids and they reject up to 25 wt % of the feed as solid coke waste which has little or no value.